ERCOT broke a three-month silence on social media Wednesday when it tweeted the release of its semiannual report that provides a 10-year forecast of its planning reserve margins.
It was the Texas grid operator’s first tweet since Sept. 13, when it said it was preparing for Tropical Storm Nicholas. The storm eventually made landfall in Texas the following day as a Category 1 hurricane, bringing heavy rainfall and storm surge before quickly falling apart quickly and dissipating on Sept. 18.
On Thursday, ERCOT also issued its first press release since Sept. 13, a sunny report that most of the generation and transmission facilities it had inspected in December were “ready” for the winter.
The burst of activity doesn’t necessarily mark ERCOT’s return to social media or sending out press releases. The Capacity, Demand and Reserves (CDR) report was dropped without the accompanying media briefing staff used to hold for both the CDR and the seasonal assessments of resource adequacy.
With the exception of the Sept. 13 notices, ERCOT’s external communications have all but dried up ever since a pair of ordinary conservation alerts in April and June spooked Texans scarred from the devastating February winter storm. A Dec. 8 press conference with Public Utility Commission Chair Peter Lake and interim ERCOT CEO Brad Jones ended abruptly before trade media calling in could ask questions, but not before Lake promised “the lights will stay on” this winter. (See Texas PUC Chair Lake: ‘The Lights Will Stay On’.)
ERCOT officials have said they are focused on “making the necessary changes to protect Texans against the next winter storm” in explaining the lengthy radio silence. Jones has put a public face on the grid operator with his Listening Tour of Texas. (See Jones Working to Restore Confidence in ERCOT.)
According to The Texas Tribune, Gov. Greg Abbott, who is up for re-election next year and is fighting off Republican primary challengers and dismal favorability numbers (with only 18% of Texas voters approving of how state leaders have handled the winter storm and its aftermath), has taken control of ERCOT’s public messaging since the storm. The Tribune said the grid operator needs approval from the governor’s office for most of its public communications, a report confirmed by people familiar with the directives coming from Abbott’s office.
Indeed, Abbott wasted no time in retweeting a Bloomberg story that picked up the winterization readiness press release. “Texas power plants have made the upgrades needed to protect against cold weather. … They are good to go,” he said.
Doug Lewin, Stoic Energy | New West Communications
“As has been a pattern lately, the communications with the public about issues of widespread concern is sorely lacking,” tweeted Doug Lewin, president of Stoic Energy and close observer of ERCOT and the PUC.
Lewin poked holes in both announcements. He complimented the inspection program for getting power plants ready for the winter, but he has frequently noted the weatherization standards won’t apply to natural gas facilities until 2023. Industry reports have been unanimous in blaming the gas industry’s failure to supply gas plants before and during the storm as being primarily responsible for the storm’s outages.
“If you can’t get fuel to it, that gas plant isn’t very useful during a cold snap,” Lewin said.
He said the latest CDR, which shows ample capacity for the grid well into the future, bases its projections on normal weather and not the freezing conditions of 2011 or 2021. He pointed out the report’s highest winter peak demand for the next five years is about 10% lower than it was under the storm’s conditions.
“To say we have enough power in normal weather is not helpful,” he said in another Twitter thread. “We should at least plan for a winter as bad as the last one. And why do we assume that we could never have a winter worse than 2021? If these reports don’t take into account extremes, they’re mostly useless.”
John Raymond Hanger, who once sat on the Pennsylvania Public Utility Commission, said he was shocked by ERCOT’s assumptions that demand won’t again reach what it did last February.
“February 2021 is now the historic winter peak within ERCOT,” he tweeted. “But in reliability planning, instead of meeting historic peak demand, ERCOT assumes such demand won’t happen during next five years. Wow!”
Inspections Find Generation Fleet ‘Ready’
ERCOT said that its system’s generation fleet and transmission companies are ready for winter weather following its on-site inspections of mandatory winterization efforts at 302 generating units and 22 transmission facilities.
ERCOT said only 10 generators, accounting for 2.1 GW (1.7% of the total fleet), had items requiring corrective measures on the day of their inspection. It said many of those items had since been completed and noted that all 10 units are still operational.
“Texans can be confident the electric generation fleet and the grid are winterized and ready to provide power,” Woody Rickerson, ERCOT vice president of grid planning and weatherization, said in a statement.
The inspections of transmission facilities found only six minor “deficiencies,” most of which have since been corrected. They focused on resources that accounted for 85% of the megawatt-hours lost during the storm. Staff plan to file a final report with the PUC on Jan. 18 for review and any potential enforcement action. Violators of the new weatherization rules face penalties of up to $1 million per day per violation. (See ERCOT Generators Near 100% Winter Readiness Compliance.)
ERCOT will conduct follow-up inspections on those generation and transmission facilities with potential identified issues. Staff and contractors have already spent more than 3,600 hours on inspection-related activities.
Final 2 Board Members Appointed
Peggy Heeg | University of Texas School of Law
The PUC said Wednesday it has filled the last two vacancies on ERCOT’s Board of Directors, completing a total makeover in the wake of the February storm.
The commission said a three-man board selected by the state’s political leadership had appointed Julie England and Peggy Heeg as ERCOT’s final two independent directors. They are also the only women on the board. A previous appointee, Elaine Mendoza, resigned in November over an apparent conflict of interest. (See Twitter Blows up over ERCOT Communications.)
England, a former senior executive with Texas Instruments, currently serves on the boards of TTM Technologies, a global technology solutions and printed circuit board fabrication company, and engineering and construction firm McMillen Jacobs Associates. She previously served as a director of the Federal Reserve Bank of Dallas from 1997 to 2003.
Julie England | Crunchbase
Heeg advised companies on energy, regulatory and corporate governance matters as an attorney before retiring. She also served on the Texas Lottery Commission and has been a director on numerous boards in the energy sector.
“This completely independent board marks a new era of reliability and accountability in ERCOT governance and leadership,” PUC Chair Lake said in a statement.
Legislation passed during the summer replaced the previous board’s five unaffiliated directors and eight market segment representatives with eight independent directors chosen by the selection committee. The ERCOT CEO, the PUC chair and the Texas Office of Public Utility Counsel’s CEO sit on the body as non-voting members.
As it heads into 2022, MISO‘s to-do list is dominated by getting major transmission built and crafting a seasonal capacity auction, direct responses to an increasingly renewable fleet and intensifying weather events.
“Don’t rest — or maybe you should rest — because we have a lot to do in the new year,” MISO CEO John Bear told stakeholders at the December board meeting, referencing the RTO’s work on its long-range transmission plan, seasonal capacity market, ongoing market platform replacement and dynamic transmission line ratings.
“I think we put MISO in a much, much better place than we were 12 months ago,” Bear said.
Seasonal Capacity on the Way
Though climate change is rarely mentioned in meetings by politically adverse MISO staff, the footprint was roiled by extreme weather in 2021, leading the RTO to conclude that a suite of resource adequacy solutions is needed for a fleet that’s either aging or has its output dictated by weather.
MISO Senior Director of Operations Planning J.T. Smith said it’s no longer surprising for the RTO to issue seasonal warnings and that it will find itself relying on non-firm imports from neighbors if outages are high when devastating cold snaps or heat domes strike.
“It’s not a new situation; it’s something we’ve reported out over the last couple of years,” Smith said in mid-December.
In February, an unprecedented winter storm forced load shed in MISO South. The RTO said the widespread artic blast gave it further justification to revise its capacity market. (See MISO: Wintry Weather Vindicates RA Changes.)
But the cold snap seemed tame in comparison to the havoc Hurricane Ida doled out to MISO South in late August. After the storm struck, MISO South stayed in conservative operations from Aug. 29 to Sept. 10 to allow for restoration. The hurricane cut through a significant transmission corridor, slashing ties from MISO into most of the Amite South and all of the Downstream of Gypsy — or metropolitan New Orleans — load pockets. MISO reported 233 transmission lines lost and 6.4 GW of generation knocked offline during the storm. (See Entergy Touts Restoration; NOLA Leaders Question Lack of Blackstart Service.)
Hurricane Ida damage in New Orleans on Aug. 30 | Entergy
“We’re still suffering down there. A lot of recovery has to happen,” Louisiana Public Service Commissioner Lambert Boissiere said at an Entergy Regional State Committee meeting Nov. 9.
In all, MISO declared conservative operations instructions for 29 days in 2021, 13 of them from Ida. The remaining days were devoted to managing intense heat or cold.
MISO recently requested FERC approval of a four-season capacity auction and corresponding reserve margin targets. That design will accompany a new capacity accreditation based upon generators’ recent availability, especially during tight conditions. The RTO has also filed separately to create a minimum capacity obligation, in which a load-serving entity must demonstrate that at least 50% of the capacity required to meet their peak load is secured ahead of the voluntary capacity auction. (See FERC Grants Comment Extension for MISO Capacity Filing.) The pair of filings pending at FERC is all but certain to attract protests from generation owners that stand to have lower capacity credits.
The RTO said it will dedicate 2022 to furthering decisions on how its markets must change to accommodate more actively managed load and a more intermittent and varied resource fleet.
Reconstruction of an Entergy tower after Hurricane Ida | Entergy
In early December, MISO’s Jordan Bakke said the current market construct will gradually become less adept at serving load. He said local power imbalances will multiply, and MISO must be able to transport power for longer distances as more wind and solar generation is built in pockets around the footprint.
MISO has said that it expects wind and solar generation to reach 30% of its total load as early as 2026, straining the system and threatening reliability. It set a new, all-time wind output record of 22 GW on Nov. 12, with wind serving 29% of total load.
Winter Apprehension
MISO is steeling itself for a reserve shortage over the winter.
RTO staff over 2021 repeated that they must make more long-lead commitments and issue maximum generation warnings more frequently as surpluses disappear under even normal weather conditions throughout the year and the bulk electric system gets more complex to manage.
Days under a maximum generation alert, warning or event in the last eight years | MISO
The grid operator has said it will likely move up instructions for members to make public appeals for energy conservation earlier in its emergency process. It’s also collecting weekly winter fuel surveys through the end of February from about 400 generators to gauge natural gas and coal fuel security. (See MISO Sounds Alarm on Potential Winter Fuel Scarcity.)
Some generation owners have criticized the weekly survey fill-in as onerous. MISO staff say they need the information to assess reliability risks this winter.
“Given the potential upside of protecting the reliability of MISO and the downside of the administrative burden, I think the upside really outweighs [the downside]. … I really appreciate MISO as a proactive manager of this situation,” Minnesota Public Utilities Commission staff member Hwikwon Ham said at the Reliability Subcommittee’s meeting Dec. 10.
MISO has estimated through an internal survey that about 11 GW of coal generation is at risk of outage this winter because of fuel supply issues.
Addressing the winter worry, Michelle Bloodworth, CEO of coal trade group America’s Power, said MISO should “reconsider how far [the coal] fleet should be allowed to shrink.” She said some coal generation can temper the “inherent risks of an overreliance on natural gas and intermittent generation for electric generation.”
“Each coal plant that retires increases MISO’s exposure to fuel assurance risk,” Bloodworth said during MISO’s Board Week in mid-December.
But the coal exodus continues unabated.
Ameren Missouri (NYSE:AEE) announced Dec. 14 that it would accelerate the retirement of its coal-fired, 1.2-GW Rush Island Energy Center to 2024. The new retirement date coincides with a deadline to install new emissions controls imposed by the U.S. District Court for Eastern Missouri. Ameren’s 2020 integrated resource plan envisioned the plant running through the end of 2039.
“Potential grid stability and reliability impacts and other downstream effects must be evaluated, and those issues that are identified must be addressed,” Ameren noted in a Dec. 14 filing. Rush Island supports voltages in the St. Louis area.
NERC estimated that MISO faces a loss of more than 13 GW in capacity by 2024, comprising 10.5 GW of coal-fired generation and 2.4 GW of gas generation. If MISO doesn’t get replacements online soon, the footprint could suffer from a combined 560-MW shortfall, NERC concluded.
New generation is clamoring in MISO’s interconnection queue. In September, generation developers’ requests to join the system pushed the queue to a 153-GW high, shattering all previous records. (See MISO Warns Queue Won’t Stay at 150-GW High.)
Historically, MISO interconnects about a fifth of the generation projects that enter the queue. MISO executives have warned that much of the new generation won’t be able to connect to the system without substantial transmission expansion.
RTO leadership has said it could advance several billions in transmission expansion for Board of Directors approval over the next few years. So far, the RTO is only prepared to propose select projects located in MISO Midwest in late spring.
MISO plans to finish an initial cost allocation design in early 2022. The allocation prescribes a separate but equal postage stamp allocation to MISO Midwest and South. The design is based on MISO’s hypothesis that benefits from long-range projects built in either Midwest or South won’t cross its subregional transmission constraint. (See MISO to Test Long-range Tx Allocation Benefits.)
Some MISO members — especially environmental proponents — have suggested that Entergy (NYSE:ETR) is opposing major transmission expansion, hoping to stave off democratization of access to its system.
MISO also faces outside pressure to get transmission towers erected.
Former FERC Commissioner John Norris — who voted in 2013 to approve Entergy’s integration into MISO to mollify a Department of Justice investigation into the company’s anticompetitive behavior — has expressed regret at his vote and admonished Entergy and its regulators’ efforts to stall the RTO’s long-range transmission planning. He asked the MISO board to intervene in what he said was the RTO’s tendency to “yield to parochial interests.”
“I did not, nor did I suspect any of my colleagues at FERC, would have thought that by late 2021, no advancement in regional transmission planning and building would have taken place. At a minimum it would’ve seemed reasonable to assume that the north-to-south interconnection issue would’ve been addressed and resolved. Without the ability to transfer substantial amounts of electricity from north to south begs the question: What’s the point?” Norris told the board in September.
Norris said MISO’s lack of regional planning means it’s “already behind in its abilities to meet the needs for 2030 and beyond.”
“Given the increase in [maximum generation] events, one could argue that MISO is not even meeting the needs of today,” he added.
SPP said last week it was once again delaying in-person meetings and staff’s return to the office because of rising COVID-19 infections and flu cases.
In a Dec. 28 message to stakeholders, CEO Barbara Sugg said SPP is cancelling the in-person option for the Jan. 10-11 Markets and Operations Policy Committee and Jan. 12 Strategic Planning Committee meetings in Oklahoma City. Those meetings will revert to the virtual format of the last two years.
The Jan. 24 Regional State Committee and Jan. 25 Board of Directors/Members Committee meetings are still planned to be held at SPP’s headquarters in Little Rock, Ark., although attendance will be limited for social distancing.
“I know this means that I will not get to see many of you in-person as soon as I hoped, but I’m confident our team will continue to facilitate virtual meetings with their usual standard of excellence,” Sugg wrote. “Be well and stay safe.”
Sugg cited a “dramatic trend” in COVID-19 infections and flu cases. She said daily new COVID cases have nearly doubled in Oklahoma since Dec. 18 and recent hospitalizations in Arkansas increased 7% in a day.
“Although early data seems to show the Omicron variant is unlikely to severely affect healthy, boosted people, we still do not know what its impact will be on older, at-risk colleagues, friends and family,” Sugg said.
The grid operator is also delaying the fourth phase of staff’s return to the Little Rock offices until at least Jan. 18 while it continues to monitor community COVID cases. It warned its plans may undergo additional modifications “to appropriately respond to changing conditions.”
California’s hydrogen fueling network serving heavy-duty trucks needs to be expanded beyond seaports to sites throughout the state and even into neighboring states if California wants to meet its zero-emission vehicle goals, speakers said during a workshop.
Ports, where heavy-duty drayage trucks pick up containers for transport to nearby locations such as rail facilities or distribution centers, are seen as a good starting point for zero-emission heavy-duty trucks. (See Decarbonizing America’s Ports Could be 1st Step for Hydrogen Adoption.)
And hydrogen fuel cell electric trucks are being introduced at the Port of Los Angeles. In June, the port announced a demonstration project that will include 10 hydrogen fuel-cell heavy-duty trucks and two hydrogen fueling stations. The trucks will be used for local pickup, delivery and drayage near the port and short regional trips in the Inland Empire. (See Fuel Cell Semis Get Road Test at Port of Los Angeles.)
But the movement of goods doesn’t stop with drayage, and some say planning must include hydrogen fueling for heavy-duty trucks at sites farther afield.
“Focusing on California only initially may be a good thing for drayage,” said Nico Bouwkamp, technical program manager for the California Fuel Cell Partnership (CaFCP).
But freight operators “frequently have opportunities to move their freight out of state,” Bouwkamp said. “They need to be able to do that … otherwise they will not invest as much in the zero-emission trucks as they are expected to.”
The comments came during a California Air Resources Board (CARB) workgroup meeting on Dec. 16 that was held as part of the process for developing the Advanced Clean Fleets regulation. The meeting focused on issues related to hydrogen, including station location planning and timing.
In developing a hydrogen-fueling network for heavy-duty trucks in California, the report says, initial efforts should focus on major freight hubs such as seaports, airports and large warehouse districts.
“The larger share of captive fleets with return-to-base operations in freight hubs will help optimize the utilization of hydrogen infrastructure, lowering fuel costs,” the report said.
The network can then be expanded by connecting the freight hubs along major corridors. California has about 500 public truck stops where some of the fueling stations could potentially be converted to hydrogen, the report said. Yet to be decided is which truck stops should be targeted first.
Working with neighboring states is also key “to reach[ing] high levels of zero-emission truck penetration in California and beyond,” the report said.
“The ports are … obviously a useful place for hydrogen,” Tim Sasseen, market development manager for Ballard Power Systems, said during the CARB workgroup meeting. “And the 5, 10, and 15 highways are going to be long-distance corridors as well. And mapping those out to existing commercial truck stops I think makes a heck of a lot of sense.”
Another meeting participant suggested looking at the West Coast Clean Transit Corridor Initiative, a partnership among electric utilities and agencies that studied how Interstate 5 from Mexico to the Canadian border could accommodate electric trucks.
The group’s report identified conceptual locations for 27 charging sites, spaced about 50 miles apart, for medium- or heavy-duty trucks. Perhaps some of those locations could also be hydrogen-fueling sites, the CARB workgroup participant said.
A California Transportation Commission representative noted during the workgroup meeting that the CTC is leading an assessment of freight corridors that would be good locations for zero-emission vehicle infrastructure, as well as potential projects to help transition to zero-emission freight. The assessment, which is a requirement of Senate Bill 671 of 2021, is due to the legislature by Dec. 1, 2023.
Advanced Clean Fleets
The Dec. 16 workgroup meeting was the second in a series of four sessions related to CARB’s Advanced Clean Fleets regulation.
The goal of the regulation is to accelerate the adoption of zero-emission trucks and buses by requiring fleets that are well-suited for electrification to transition to ZEVs where feasible.
According to CARB, the regulation would help reach the goals in Gov. Gavin Newsom’s 2020 executive order that calls for 100% zero-emission drayage trucks by 2035; and 100% zero-emission medium- and heavy-duty vehicles by 2045 where feasible.
CARB released an informal discussion draft of the regulation in September. Under the preliminary proposal, cities, counties, special districts and state agencies would be required to buy ZEVs when they add new vehicles to their fleets.
Starting in late-2023, CARB would allow only zero-emission drayage trucks to be added to its drayage truck registry. And by 2035, all drayage trucks would be required to be zero-emission.
Under the proposal, fleets designated as high-priority would be required to hit percentage-ZEV targets, starting with vehicle types that are most suitable for electrification. High priority fleets would include those of 50 or more vehicles, or those whose owner has $50 million or more in gross annual revenue.
The regulation would apply to vehicles weighing more than 8,500 pounds.
CARB has scheduled additional workgroup meetings for Advanced Clean Fleets on Jan. 12 and Jan. 19. The first of those sessions will focus on electricity and the grid; the second will focus on costs and funding.
Reversing FERC, the D.C. Circuit Court of Appeals ruled Dec. 28 that developers of the abandoned Potomac-Appalachian Transmission Highline (PATH) transmission project must refund $6 million spent to influence public officials to approve the project (20-1324).
The $2.1 billion, 765-kV “coal by wire” PATH project was approved by PJM in 2007 to run from American Electric Power’s (NASDAQ:AEP) John Amos coal generator in St. Albans, W.Va., to New Market, Md.
By 2011, however, PJM said the need for the line had moved several years beyond 2015 because of reduced load growth following the Great Recession. After ordering transmission owners to suspend work on the line pending a more complete analysis, the PJM Board of Managers terminated it in 2012. PATH’s developers, AEP and FirstEnergy’s (NYSE:FE) Allegheny Energy, sought to recover $121.5 million they spent on the abandoned project.
At issue was $6 million that PATH passed on to customers in 2009-2011 for public relations and advocacy activities related to its effort to win certificates of public convenience and necessity to build the line.
After denying recovery of the expenses in 2017, FERC reversed itself in a ruling in January 2020 (Opinion 554-A, ER09-1256, et al.). (See FERC Grants Recovery on PATH Project Costs.) FERC later rejected a rehearing request by PATH opponents Keryn Newman and Alison Haverty of West Virginia (Opinion 554-B), prompting them to file a pro se petition with the D.C. Circuit.
PATH booked the expenses in accounts designated for “Outside Services Employed” and “General Advertising Expenses.”
But Judge Cornelia “Nina” Pillard, writing for a three-judge panel, agreed with the petitioners that the expenses belonged in Account 426.4 for “Expenditures for Certain Civic, Political and Related Activities,” which would exclude them from being passed through to ratepayers.
FERC’s instructions state that 426.4 “shall include expenditures 1) for the purpose of influencing public opinion with respect to the election or appointment of public officials, referenda, legislation or ordinances (either with respect to the possible adoption of new referenda, legislation or ordinances or repeal or modification of existing referenda, legislation or ordinances), or approval, modification or revocation of franchises; or 2) for the purpose of influencing the decisions of public officials.”
PATH contended that account was intended only for expenses made to directly influence the decisions of public officials but that the spending was for “indirect” influence.
FERC agreed, saying the spending was more like an “operating expense” because it related to “general promotional efforts” on behalf of a line that had already been approved by PJM.
The commission said the spending would have belonged in Account 426.4 if it was intended to win “a franchise application — in which the utility competes for a potentially lucrative status for itself” — rather than an application “in service of an RTO-approved project — in which the utility represents not only its own interests but those of the RTO as a whole.”
But the court said FERC’s reasoning was “unpersuasive,” noting that PATH’s own internal statements confirm that the spending was intended to influence the decisions of public officials.
“FERC clearly erred in reading Account 426.4’s second clause as implicitly limited to expenditures for the purpose of directly influencing the decisions of public officials,” Pillard wrote. “We hold that the official-decisions clause includes expenditures for the purpose of indirectly as well as directly influencing the decisions of public officials. … Because indirect influence of state officials responsible for certification decisions was the undeniable purpose of the expenditures at issue here, they should have been assigned to Account 426.4.”
The court vacated FERC’s opinions and remanded the case to the commission.
ISO-NE took several important steps to demonstrate its “alignment” with state climate policies in 2021. But the RTO’s stakeholder meetings remain closed to the public, and its board elections remain secret, falling short of calls for increasing transparency. And this spring, the states and the RTO will be debating differing market proposals for accomplishing the states’ clean energy goals.
Which design will prevail is just one of the questions facing New England in 2022, starting with whether it will have enough natural gas to keep the lights on through the winter. Among the others: whether Maine voters’ rejection of the New England Clean Energy Connect (NECEC) transmission line will stick, and whether the 650-MW gas-fired Killingly plant in Connecticut will get built.
Here’s a look back at the big issues of 2021 and what to expect in 2022.
Resource Adequacy Concerns
On Dec. 6, ISO-NE officials gave a sobering press briefing, warning that limited natural gas pipeline capacity and global supply chain issues put the New England grid at heightened risk of load sheds this winter.
The RTO said it can meet forecast peak demand of 19,710 MW during average winter weather conditions of 10 degrees Fahrenheit and 20,349 MW if temperatures reach below-average conditions of 5 F. But ISO-NE CEO Gordon van Welie said uncertainty over fuel supplies “could put the region in a more precarious position than past winters and force the ISO to take emergency actions up to and including controlled power outages.” Van Welie said the outages would be a last resort “to prevent a regionwide blackout, which would take many days or weeks to restore.” (See ISO-NE: New England Could Face Load Shed in Cold Snaps.)
Resource adequacy has been a recurring winter concern in New England because of difficulty siting new natural gas pipelines and electric transmission. The state-RTO tensions were on display at FERC’s technical conference on modernizing electricity market design in ISO-NE in May (AD21-10).
Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection, complained that the RTO had failed to prevent the premature retirement of the Millstone nuclear plant, leaving her state to “shore up the reliability of the [ISO-NE] grid and the market” by approving subsidies funded by ratepayers.
Van Welie told the conference that markets are “never going to work very well” with inadequate infrastructure supporting them “or if policy objectives are not aligned.”
“We have to design the markets around those [pipeline and transmission] constraints,” he said. “That’s just where we ended up because of the choices we made over the last two decades.
“Until the region figures out how it wants to socialize some of these costs for reliability that are outside of the market, we’re going to stay stuck in that situation,” he added. “There’s no market design that will solve the problem that Commissioner Dykes wants us to solve.” (See Regulators, ISO-NE Discuss Market Changes at FERC Tech Conference.)
Progress on States’ Wish List
ISO-NE took several steps in 2022 to address the states’ demand for changes to the RTO’s wholesale market design, transmission planning and governance. The demands, first spelled out in a joint statement by five of the region’s governors in October 2020, was updated by the New England States Committee on Electricity (NESCOE) last August in its “Advancing the Vision” report.
ISO-NE’s priorities for 2022 | ISO-NE
ISO-NE’s Board of Directors responded to the states’ demands in September, saying it was “pursuing targeted governance and communications enhancements, consistent with its independence and oversight role.” It assured NESCOE that it is “aligned with the states on the clean energy transition,” citing a list of transmission planning and market rule initiatives that it was pursuing to enable the transition.
In November, ISO-NE presented the scope of its work for the 2050 Transmission Study, which will examine ways to incorporate clean energy and distributed energy resources beyond the RTO’s standard 10-year planning horizon. The study will seek to determine what transmission is needed to serve load while satisfying reliability criteria for 2035, 2040 and 2050, including high-level cost estimates to help the states evaluate different transmission options. The study was requested by NESCOE, which also was responsible for many of the study assumptions. (See ISO-NE Presents Preliminary 2050 Tx Study Scope.)
Work is expected to continue on the study throughout 2022. As also requested by NESCOE, ISO-NE on Dec. 27 filed proposed tariff changes to permit future state-led, scenario-based transmission planning as routine practice (ER22-727).
In addition, ISO-NE expects to release a report this spring on the RTO’s Future Grid Reliability Study (FGRS), which will identify potential reliability gaps in 2040 based on current state laws and policies. The FGRS, which is not a detailed transmission study, is largely based on assumptions developed by NEPOOL stakeholders, with input from NESCOE. A draft of the FGRS is expected to be presented at the Planning Advisory Committee in April and discussed at NEPOOL’s Markets Committee/Reliability Committee meeting in May.
The RTO also is conducting cluster studies to interconnect offshore wind on Cape Cod and a pilot study to proactively plan for growing levels of DERs, renewables, imports and energy storage.
Wholesale Market Design
In April, the RTO is expected to release its Pathways to the Future Grid study, which will evaluate alternative market frameworks for adapting to state energy policies. The analysis will include a forward clean-energy market (FCEM): a centralized, forward auction favored by states in which buyers (states, cities, retailers, companies and utilities) could voluntarily purchase clean energy attribute credits.
The study also will examine the RTO’s net carbon pricing proposal, which would require suppliers pay for each unit of carbon they emit to generate electricity, as a supplement to the Regional Greenhouse Gas Initiative.
Stakeholders and ISO-NE staff spent many meetings during 2021 discussing the RTO’s Order 2222 compliance filing and eliminating the minimum offer price rule (MOPR).
In December the NEPOOL Markets Committee approved ISO-NE’s proposed set of market rules to implement Order 2222 — which requires RTOs to allow DER aggregations to provide all wholesale services that they are technically capable of providing — and rejected several amendments opposed by the RTO.
The compliance filing passed the MC with unanimous support from the Generation, Transmission and Publicly Owned Entities sectors and most Suppliers. Alternative Resources were split, and End Users, who had supported unsuccessful amendments by Advanced Energy Economy, were unanimously opposed.
Assuming that FERC accepts the compliance filing by the fourth quarter, distributed capacity resources will be able to participate in Forward Capacity Auction (FCA) 18 in February 2024. The RTO proposed a fourth-quarter 2026 effective date for the energy and ancillary services markets.
The Participants Committee is scheduled to vote on the Order 2222 changes Thursday. The filing is due Feb. 2.
Meanwhile, the Markets Committee is scheduled to vote on the RTO’s proposal to eliminate the MOPR at its first meeting of the new year, Jan. 11-12.
NESCOE, FERC Chair Richard Glick and Commissioner Allison Clements all favored eliminating the MOPR, which they said was undermining state decarbonization efforts. Stakeholders approved the change in November, despite warnings from merchant generators and ISO-NE’s Internal Market Monitor that it will suppress capacity prices. Other stakeholders debated whether the implementation of the RTO’s plan should be delayed until it approves long-term market rule changes on capacity accreditation and reserves. The MOPR would be eliminated beginning with FCA 17 in 2023. (See Monitor, Merchants Challenge ISO-NE Plan to Eliminate MOPR.)
State-RTO Communications
ISO-NE’s September response to NESCOE said the RTO’s board is “making changes that are consistent with the ISO’s core requirement for independence and its role as an oversight board.”
It pledged the board will hold an annual open meeting beginning in 2022 — focused on the electricity markets on even-numbered years and transmission planning in odd-numbered years — in addition to meetings the board holds with the states and NEPOOL sectors throughout the year.
The board said it would hold other meetings as needed to discuss consumer implications of its proposals and that if the states have a majority position on an RTO proposal, “management will include consideration of a state majority position in filings to FERC.”
It also noted that the CEO’s monthly board reports — which summarize recent board and board-committee meetings — are public and that states can question van Welie about board activities at NEPOOL Participants Committee meetings.
But the board did not take action on NESCOE’s request to establish a standing board committee on state and consumer responsiveness. “The board is continuing discussions with the states about this request,” ISO-NE said in an email to RTO Insider. “The board and several of its committees already review state and consumer issues in various ways, and the board is continuing to consider other targeted enhancements.”
Nor were there any changes to how ISO-NE selects its board members. NESCOE had called on FERC to revise Order 719 to ensure “that states and consumers in New England are meaningfully represented” in the composition of the board and the Joint Nominating Committee process that governs board nominations. State officials have only one vote on the 14-member committee, through the New England Conference of Public Utilities Commissioners.
“The Joint Nominating Committee is governed by the Participants’ Agreement between the ISO and NEPOOL stakeholders,” the RTO said. “The board cannot make unilateral changes to the process for selecting new members. Any changes would need to be pursued through the NEPOOL stakeholder process and approved by FERC.”
In September, ISO-NE announced the election of four board members for three-year terms: incumbent Michael Curran and newcomers Caren Anders, Steve Corneli and Catherine Flax. The board also elected former FERC Commissioner Cheryl LaFleur as its chair, replacing the retiring Kathleen Abernathy.
Transparency Still Lacking, Critics Say
Critics were unimpressed with the RTO’s modest changes on transparency, noting that New England remains the only region in the U.S. whose RTO/ISO stakeholder meetings are closed to the public.
ISO-NE and NEPOOL have “essentially privatized public policymaking,” Tyson Slocum, director of Public Citizen’s energy and climate program, said at the RTO’s quarterly Consumer Liaison Group meeting in September. “There is inadequate transparency and accountability in these institutions that don’t reflect the public interest nature of what they’re doing.”
Rebecca Tepper, chief of the Energy and Telecommunications Division in the Massachusetts Attorney General’s Office, also lamented the lack of progress. “I think it would be good to see that move forward and have some real dialogue about how the governance process can be more accommodating to people.” (See Stakeholders Still Seeking Transparency from ISO-NE, NEPOOL.)
FCA 16
In the near term, capacity market watchers are waiting for a FERC ruling on ISO-NE’s request to prevent the 650-MW natural gas-fired Killingly Energy Center in Connecticut from participating in FCA 16 in February and to terminate its capacity supply obligations (CSO). Killingly, which initially secured a CSO in 2019’s FCA 13 for the 2022/23 capacity commitment period, failed to meet its development milestones, the RTO said (ER22-355).
Developer NTE Energy responded that ISO-NE made an incorrect assumption regarding a financing milestone date, claiming that its financing is “imminent.” In its Dec. 3 protest to FERC, NTE called the RTO’s action “premature” and said it had kept the project moving despite “challenges beyond its control, including the COVID-19 pandemic and an ultimately unsuccessful 29-month challenge to its state siting certificate.” ISO-NE responded on Dec. 20, saying the only question facing FERC was whether the plant can reach commercial operation by June 1, 2024. “The answer … is ‘no,’” said the RTO.
“There is also no dispute that to terminate Killingly’s capacity supply obligation — a valuable asset worth hundreds of millions of dollars — ISO-NE’s tariff requires the ISO to prove that Killingly would not enter service before the June 1, 2024 deadline,” NTE responded Dec. 28. “Despite its burden, to date, the ISO has offered only speculation about what might happen — repeating in its answer that it just ‘lost confidence’ in the project.”
FCA 16 also will see the end of the seven-year price lock for new entrants. FERC ruled in late 2020 that the rules, which had been in effect since the FCA began in 2006, resulted in “unreasonable price distortion” and that locked-in prices are “no longer required to attract new entry.” (See FERC Orders End to ISO-NE Capacity Price Locks.)
Prices in FCA 15 cleared at $2.48 to $3.98/kW-month — the high in Southeast New England nearly doubling 2020’s record-low figure.
Turbulent Year for Avangrid
2021 was a turbulent year for Avangrid (NYSE:AGR), the parent of Central Maine Power (CMP) and United Illuminating in Connecticut.
In May, the Bureau of Ocean Energy Management approved the final permit for 800-MW Vineyard Wind I, a joint venture of Avangrid Renewables and Copenhagen Infrastructure Partners. The first commercial-scale offshore wind project in the U.S., Vineyard Wind broke ground in November and is expected to begin commercial operation in 2023. In December, Massachusetts said it would purchase 1,200 MW of OSW from Vineyard Wind’s Commonwealth Wind project. (See Mass. Adds 1,600 MW to OSW Portfolio in Latest Procurement.)
Avangrid faced two setbacks late in the year, however.
In November, CMP halted construction on the NECEC transmission project in response to Maine voters’ approval of a referendum to block it. Avangrid filed a lawsuit challenging the constitutionality of the referendum. On Dec. 16, a judge rejected the company’s request for an injunction to block the impact of the referendum.
Central Maine Power halted construction on the New England Clean Energy Connect transmission line in November following Maine voters’ approval of a referendum to block the project. | New England Clean Energy Connect
In December, New Mexico regulators rejected Avangrid’s proposed $8.3 billion acquisition of PNM Resources (NYSE:PNM), citing Avangrid’s “demonstrated record of poor performance” in other states, including its stewardship of CMP.
The New Mexico Public Regulation Commission’s 5-0 vote also followed allegations by a former cybersecurity contractor that the company conspired with suppliers to buy “tens of millions” in overpriced and unnecessary security equipment and services to boost profits. (See NM Regulators Reject Avangrid-PNM Merger.)
Regulators in Connecticut and Maine said they would review the allegations, which came six months after Maine Gov. Janet Mills vetoed legislation to create a publicly owned utility to replace CMP and Versant Power, calling it “hastily drafted.” (See Mills Tells Maine Legislature to Slow Down on Plan to Replace IOUs.)
Annual Work Plan
ISO-NE’s Annual Work Plan lists several additional projects and timelines for 2022:
The RTO is expected to file a proposal with FERC by the end of 2022 revising resource accreditation in the capacity market, to be effective in FCA 18, with a second filing by the end of 2023, targeting FCA 19.
The RTO will focus in 2022 on proposals to co-optimize reserves in the day-ahead energy markets.
Beginning in the first quarter and extending into 2023, the RTO will work with stakeholders and the Electric Power Research Institute on ways to model high-impact reliability risks (tail risks) related to extreme weather events, an initiative prompted by the outages in Texas during the February 2021 winter storm.
The RTO expects to file changes with FERC in 2022 allowing solar resources to take electronic dispatch instructions in the real-time energy market under the Do-Not-Exceed model currently used by wind resources. The change would be effective in the second quarter of 2023.
ISO-NE plans to begin discussing tariff changes in the first quarter to allow storage-as-transmission solutions for needs assessments or public policy transmission studies.
It also hopes to complete its two-year nGEM Day-Ahead Market Clearing Engine Implementation project this year. The day-ahead clearing engine is expected to be in-service Q1 2023.
The RTO will complete three projects in 2022 concerning identity and access management; security information and event management; and a refresh of the hardware and software supporting the collection of network traffic data that feed the Network Intrusion Detection system and the Security Information and Event Management analysis system.
Gov. Jay Inslee last month approved the 80-MW Goose Prairie solar farm to be built in Central Washington.
“I believe this project is appropriately sited, and that the site certificate is legally adequate,” Inslee wrote in a Dec. 20 letter to the Washington Energy Facility Site Evaluation Council (EFSEC), which in November recommended the governor approve the project. (See Siting Council Endorses Central Wash. Solar Farm.) Inslee said the project is environmentally sound for the land it will occupy.
The project by OneEnergy Renewables (OER) of Seattle would be located near the town of Moxee in Yakima County. Goose Prairie’s application states that the 625-acre solar farm would interconnect with the Bonneville Power Administration’s 115-kV Midway-to-Moxee transmission line. The company is also retaining the option for a battery-storage system that would not exceed the 80-MW capacity of the project.
Inslee’s letter said the EFSEC did eventually consider the Yakama Nation’s concerns about the project’s effects on wildlife migration and the tribe’s access to the area for cultural reasons.
But “the council was not able to directly engage in early, ongoing and thorough government-to-government consultation with tribal governments,” Inslee added. Inslee wrote that EFSEC needs a more formal mechanism for consulting with the appropriate tribes on the effects on solar and wind turbine proposals.
Now, OER must study the environmental impacts to any habitats for sensitive species and provide a mitigation plan, according to paperwork filed with the EFSEC. The council and the Washington Department of Fish and Wildlife would have to approve that plan. An EFSEC public hearing on the project held March 16 showed no opposition.
Central and Eastern Washington have four solar farms going through permitting, 28 on the drawing board, two under construction, and one in operation, according to state estimates. EFSEC is currently reviewing nine proposed wind and solar projects for the state.
The Nuclear Regulatory Commission is preparing to cite Energy Harbor, the owner of the Davis-Bessie nuclear power plant in Ohio, for failure to develop a preventative maintenance schedule for electric switches installed in 2006.
The field flash selector switches (FFSS) enable the plant’s two emergency diesel generators (EDGs) to actually begin to produce electricity once their turbines are spinning.
A team of NRC inspectors earlier this fall determined that the switches had not been inspected in the 15 years since installation and that “degradation” of electrical contact surfaces had occurred.
Each EDG is designed to power the plant’s complex safety systems, including the emergency cooling equipment, if the reactor shuts down and the facility is also cut off from grid power. Their functioning in an emergency shutdown is crucial. They failed to generate power during five routine periodic tests between 2019 and 2021, the company reported.
The EDG problems and a July incident that began with the plant’s main steam generator, causing the reactor to automatically and safely switch off, prompted NRC to send a special inspection team to the plant, located about 30 miles east of Toledo on Lake Erie.
Davis-Bessie’s own engineers had determined that two other switches were not designed for the plant’s EDG system, and they were replaced. But the plant’s management disagreed with NRC’s finding that its failure to develop an inspection of the FFSS had caused the problem.
“After the special inspection concluded and during the development of the preliminary significance determination, you provided the perspective, based on a vendor analysis, that the EDG FFSS failure during the fast-start test was most likely the result of foreign material between the switch electrical contacts, as evidenced by the presence of nickel on the contact surface,” the commission noted in a letter sent to Davis-Besse managers Dec. 16 and released to the public Monday.
“You concluded that the failure was not caused by the lack of inspection and long-term switch electrical contact degradation. The NRC has preliminarily determined this vendor analysis does not rule out contact degradation due to lack of inspection as a significant contributing cause of the failure,” the commission countered.
“There is sufficient operating experience on electrical contact failure due to contamination to reasonably consider this degradation mechanism to be credible. Therefore, we continued to conduct our significance determination with this assumption.”
If NRC does cite the company as it appears ready to do, the citation would remain on the plant’s safety record while the commission conducts additional on-site inspections. The commission is attempting to assess the risk the problem with the switches posed.
Energy Harbor did not respond to a request for comment.
An RTO could provide Oregon with economic, planning and operational benefits, but it would not serve as a “universal problem-solver” for the growing challenges facing the state’s electricity system, according to a study the Oregon Department of Energy (ODOE) delivered to the state legislature Monday.
And bringing Oregon into an RTO would present challenges of its own, the report says. Chief among them: ensuring a market and governance design that balances the state’s “diverse interests,” guarantees a “meaningful role” for those interests, and preserves state clean energy and equity goals.
But the ODOE study also casts a favorable light on Oregon’s increased participation in regional collaboration across the power sector. It highlights the various regionalization efforts already taking shaping across the Western Interconnection and emphasizes the importance of Oregon entities continuing to play a role in their progress.
It also points out that, unlike previous efforts to develop organized electricity markets in the West, “the current momentum toward increased regionalization has a unique sense of drive and urgency … driven by transformational changes in the electric sector — from the rapid deployment of increasingly cost-effective wind and solar energy, to the retirement of coal plants in Oregon and across the West, to the adoption of state clean energy mandates.”
In developing the study, ODOE said it “identified broad common interest among Oregon stakeholders” to build on that momentum “to explore increased regional collaboration and coordination in the electric sector.”
The study also advises lawmakers that the “nuanced perspectives” among various stakeholders “would need to be carefully considered in designing an RTO that could deliver benefits to Oregon retail customers.”
A Colorado Public Utilities Commission study released early this month, the product of a 2019 law, found that utilities in that state could save between $50 million and $230 million annually from joining an RTO. (See Colo. PUC: State Could Save up to $230M in Wholesale Market.) A different multistate-led study published earlier this year found the West as a whole could save up to $2 billion a year by 2030 through the development of a single RTO. (See Study Shows RTO Could Save West $2B Yearly by 2030.)
But ODOE was not charged with creating an economic benefits report, nor was it expected to make recommendations about whether the state should compel its utilities to join an RTO, Adam Schultz, electricity and markets policy lead at the department, said during the first meeting of the state’s RTO Advisory Committee, whose representatives helped guide development of the study. (See Oregon RTO Committee Ponders Paths to Regionalization.)
Instead, the goal was “to gather and synthesize the range of perspectives on the benefits, costs, opportunities, challenges and risks of RTO formation that exists among a diverse range of Oregon stakeholders to inform the state legislature and other interested parties,” Schultz said.
In that vein, the ODOE study provides lawmakers with a primer on RTOs, describing the role of an organized market in the buying and selling of energy, the procurement of capacity (or not), and the planning and operation of transmission networks.
The study also outlines the regionalization efforts already in motion. “Given recent industry trends, including coal plant retirements and the need for flexible capacity that can integrate increasing amounts of variable wind and solar generation, significant momentum has built in recent years to increase regional cooperation,” the report said, citing CAISO’s expanding Western Energy Imbalance Market (WEIM), SPP’s increasing market offerings in the West and the Northwest Power Pool’s (NWPP) Western Resource Adequacy Program, which will roll out next year. (See Implementation Underway for NWPP’s Western RA Market.)
Membership in an RTO would represent a qualitative step beyond those efforts because conventional organized markets require member utilities and transmission owners to surrender operational control of their transmission systems to a central operator, which would also assume the role of grid planner.
The ODOE study highlighted a debate that occurred within the RTO Advisory Committee, in which Ravi Aggarwal, a manager with the Bonneville Power Administration, urged the region to take “a more incremental and staged approach” to forming an RTO, given that the “three-legged stool” of planning, resource adequacy and markets are all currently being served by NorthernGrid, NWPP and the WEIM, respectively.
“Some committee members believe that the incremental steps to increase regionalization could lead the region to formation of an RTO. The incremental approach may be helpful and necessary to build the trust required among a diverse set of stakeholders to make formation of a sufficiently large and well governed RTO possible,” the study said.
Other members said an incremental approach could allow participants to take an “a la carte” approach to regionalization, “participating only up to their comfort level up to and including membership in an RTO.”
But still other members were wary of such an approach, the study pointed out, warning that it could fail to deliver the full benefits of an arrangement that coordinates many functions within a single body. “The region may also be approaching the limits of how many additional incremental steps (and therefore additional benefits) can be bolted-on to the status quo,” the report said.
The report also advised that while RTO formation could yield operational benefits for the transmission system, particularly through improved utilization and transparency, it would not necessarily solve challenges around cost allocation, siting or permitting.
“Multiple members of the committee noted the development timelines for major new transmission projects can often be in the 10- to 20-year range due primarily to challenges around siting and permitting. An RTO would not necessarily resolve these timeline challenges,” the study said.
The report additionally pointed to an RTO’s potential to improve utilization of existing renewable resources through reduced curtailments, as well as its ability to provide customers with greater access to low-cost out-of-state renewables. However, committee members widely agreed that state policies and declining costs would continue to drive the adoption of renewables regardless of the existence of an RTO.
Comes Down to Design
But the ODOE study advised lawmakers that the key challenge to forming an RTO would be political rather than technical or operational.
“One of the key perspectives shared by committee members was the criticality of negotiating the details of market design and governance structures to weigh trade-offs, balance multiple interests, and identify pathways to achieve optimal outcomes,” the study said. Those trade-offs would occur in and among:
states, with their varying policy priorities and regulatory requirements;
load-serving entities, which in Oregon consist of three investor-owned and 38 consumer-owned utilities;
independent power producers, power marketers and transmission owners;
advocacy organizations, such as trade groups, environmental and social justice organizations, and labor unions; and
retail customers.
An RTO would also have to contend with the presence of BPA, which owns and operates about 75% of the region’s transmission system.
“This makes BPA a critical but largely voluntary participant in regional conversations around RTO formation, although the actions of neighboring utilities in the region or of other parts of the federal government (e.g., [the U.S. Department of Energy], FERC or Congress) can affect the decisions of BPA,” the report said.
It also cautioned lawmakers that “careful design” of an RTO would be necessary to prevent an erosion of state authority while also helping Oregon to achieve its environmental policy objectives.
RTO Advisory Committee members generally agreed that an RTO would provide an “additional tool” for helping Oregon achieve its target of generating 100% emissions-free electricity by 2040, according to the report.
“Several members of the committee went even further to suggest that RTO formation may be necessaryto achieve those targets,” the report said.
A group of consumer advocates requested rehearing Monday of FERC’s decision in November to open a paper hearing on PJM transmission owners’ proposal to add network upgrades to their rate base (ER21-2282).
The Maryland Office of People’s Counsel, the D.C. Office of the People’s Counsel and the Delaware Division of the Public Advocate argued the TOs do not have “exclusive and unilateral rights to file under Section 205” of the Federal Power Act to change network upgrade rules in the tariff, “particularly the rules impacting major elements of the market structure such as those relating to network upgrades affected in this proceeding.”
“There are good public policy reasons for the existing division of filing rights,” the advocates said. “Significant changes to PJM market design should be carefully considered by all stakeholders in the PJM market, either through a stakeholder process or their interactions with the RTO. This process allows PJM and, through its review of PJM’s filing, the commission to receive a balanced perspective that considers generation and consumer interests as well as those of transmission owners. The PJM TOs’ unilateral filing rights, which by definition are necessarily parochial in nature, are appropriately limited to areas related to rate design and revenue adequacy.”
The TOs had asked the commission on June 30 to allow them the option to fund network upgrades and add them to their rate bases. Under PJM’s “participant funding” model approved in 2004, generators provide the capital for network upgrades, while the additional infrastructure is added to rate bases at zero cost, allowing TOs to recover only their operations and maintenance expenses from network transmission customers. (See FERC Establishes Paper Hearing on PJM Rate-base Network Upgrades.)
The advocates said the tariff modifications would impede PJM’s “exclusive rights to change terms and conditions related to billing and cost recovery” because they would change how the RTO collects payments for network upgrades. They also said FERC’s order “interferes” with PJM’s responsibility to review public policy objectives when evaluating projects and needs in the Regional Transmission Expansion Plan.
“The authority granted to the PJM TOs by the November 2021 order must be part of a market design that is consistent with or superior to the market design approved in Order No. 2003, but, as reflected in the June 30 filing, it is not,” the advocates said.
FERC previously set a deadline of Jan. 3 for initial responses to its November order, but the TOs filed a motion earlier this month to extend the deadline to Jan. 13 for initial responses and Feb. 28 for reply comments because of the holiday season and a compressed time frame. The commission accepted the deadline extension request on Dec. 9.
Doug Lewin, Stoic Energy | New West Communications
Peggy Heeg | University of Texas School of Law
